Electric power is generated at a power station and transmitted through a transmission network of high voltage lines. These lines may be hundreds of miles in length, and deliver the power into a common power pool called a “grid.” The grid is connected to load centers (e.g., cities) through a sub-transmission network of normally 33 kV (or sometimes 66 kV) lines.
FIG. 1 is a diagram illustrating a conventional power transmission and distribution system. This diagram is an example of one of variety of known grid topologies and is provided for illustration purposes. Referring to FIG. 1, high voltage lines terminate in a 33 kV (or 66 kV) substation, where the voltage is stepped-down to about 11 kV for power distribution to load points through a distribution network of lines at 11 kV and lower. The power network is the distribution network of 11 kV lines or feeders downstream of the substation. Each 11 kV feeder which emanates from the 33 kV substation branches further into several subsidiary 11 kV feeders to carry power close to the load points (localities, industrial areas, villages, etc.). At these load points, a transformer further reduces the voltage from 11 kV to 415V to provide the last-mile connection through 415V feeders to individual customers, either at 240V (as a single-phase supply) or at 415V (as a three-phase supply). A feeder could be either an overhead line or an underground cable.
At the feeder level, the electric grid is polyphase (i.e., having multiple lines for different phases). At a customer endpoint that takes in a single phase (e.g., a residence), a physical line connects to a meter located at the customer endpoint. However, when the customer endpoint is physically connected, it may not necessarily be known at that time which phase at the feeder level corresponds to the line at the customer endpoint to which the meter is being connected. This could be because the utility may have never had that information, or it may not have been kept up to date since physical grid topology is typically modified over time. Further, if there is a power outage, or if the power is shut down so that a new transformer can be installed, there is no guarantee that the meter at the customer endpoint device will be on the same phase as it was previously.
The utility can calculate losses and theft by comparing the usage at the feeder level with aggregated usage on the customer side. But without knowledge of the real grid topology, this information could be at least three times less accurate. As the customer density served by a feeder increases, this inaccuracy may increase, and thus, may result in an increased loss of power and revenue to the utility.